Method and system for running barrier valve on production string

ABSTRACT

A completion system, including a lower completion initially fluidly open. A production string is included having a removable plug configured to impede fluid flow through the production string. The removable plug is run in with the production string. An intermediate completion assembly is included that couples the lower completion to the production string. The intermediate completion assembly has a packer device and a barrier valve. The packer device is operatively arranged to be set by pressurizing fluid in the production string against the removable plug. The barrier valve is operatively arranged for selectively impeding fluid flow between the production string and the lower completion after the removable plug is removed. A method of completing a borehole is also included.

BACKGROUND

Current practice for completing downhole structures, particularlydeepwater wells, involves stimulating, hydraulic fracturing, fracpacking and/or gravel packing one or more zones and then landing a fluidisolation valve, typically a ball valve system, above the treated zones.The fluid isolation valve temporarily blocks fluid flow so that an uppercompletion string can be run and connect the treated zones to surfacefor enabling production after the fluid isolation valve is opened.Although such systems do generally work for their intended purposes,they are not without limitations. For example, these known ball-typefluid isolation valves do not provide an efficient and reliable systemfor periodically replacing portions of the upper completion, and mayrequire wireline intervention, hydraulic pressuring, or the runningand/or manipulation of a designated tool to control the fluid isolationvalve. For example, artificial lift systems (e.g., electric submersiblepumping systems or ESPs), are increasingly desirable, particularly foruse in deepwater wells. Accordingly, advances in downhole valvetechnology, at times referred to as “mechanical barriers”, particularlyfor deepwater wells and/or for enabling more reliable and efficientreplacement of upper completion systems and components, are always wellreceived by the industry.

SUMMARY

A completion system, including a lower completion initially fluidlyopen; a production string having a removable plug configured to impedefluid flow through the production string, the removable plug being runin with the production string; and an intermediate completion assemblycoupling the lower completion to the production string, the intermediatecompletion assembly having a packer device and a barrier valve, thepacker device operatively arranged to be set by pressurizing fluid inthe production string against the removable plug, the barrier valveoperatively arranged for selectively impeding fluid flow between theproduction string and the lower completion after the removable plug isremoved.

A method of completing a borehole including running a production stringhaving a removable plug disposed therewith downhole, an intermediatecompletion assembly disposed with the production string; coupling theproduction string to a lower completion with the intermediate completionassembly, the lower completion initially fluidly open; impeding fluidflow between the production string and the lower completion with theremovable plug; setting a packer device by pressurizing fluid in theproduction string against the removable plug; removing the removableplug; and impeding fluid flow between the production string and thelower completion with a barrier valve of the intermediate completionassembly.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way.With reference to the accompanying drawings, like elements are numberedalike:

FIG. 1 is a partial cross-sectional view of a completion system in whichan intermediate assembly is being engaged with a lower completion;

FIG. 1A is an enlarged view of the area circled in FIG. 1;

FIG. 2 is a partial cross-sectional view of the completion system ofFIG. 1 in which the intermediate assembly is engaged with the lowercompletion;

FIG. 3 is a partial cross-sectional view of the completion system ofFIG. 1 in which a barrier valve of the intermediate assembly is closedfor testing a packer of the intermediate assembly;

FIG. 3A is an enlarged view of the area circled in FIG. 3;

FIG. 4 is a partial cross-sectional view of the completion system ofFIG. 1 in which a fluid isolation valve for the lower completion isopened;

FIG. 5 is a partial cross-sectional view of the completion system ofFIG. 1 in which a work string on which the intermediate assembly wasrun-in is pulled out, thereby closing the barrier valve of theintermediate assembly;

FIG. 6 is a partial cross-sectional view of the completion system ofFIG. 1 in which a production string is being run-in for engagement withthe intermediate assembly;

FIG. 7 is a partial cross-sectional view of the completion system ofFIG. 1 in which the production string is engaged with the intermediateassembly for opening the barrier valve and enabling production from thelower completion;

FIG. 8 is a partial cross-sectional view of the completion system ofFIG. 1 in which the production string has been pulled out, therebyclosing the barrier valve of the intermediate assembly and a subsequentintermediate assembly is being run-in for engagement with the originalintermediate assembly;

FIG. 9 is a partial cross-sectional view of the completion system ofFIG. 1 in which the subsequent intermediate assembly is stacked on theoriginal intermediate assembly;

FIG. 10 is a partial cross-sectional view of a completion systemaccording to another embodiment disclosed herein; and

FIG. 11 is a partially cross-sectional view of a completion systemaccording to another embodiment disclosed herein.

DETAILED DESCRIPTION

A detailed description of one or more embodiments of the disclosedapparatus and method are presented herein by way of exemplification andnot limitation with reference to the Figures.

Referring now to FIG. 1, a completion system 10 is shown installed in aborehole 12 (cased, lined, open hole, etc.). The system 10 includes alower completion 14 including a gravel or frac pack assembly 16 (ormultiples thereof for multiple producing zones) that is isolated from anupper completion 18 of the system 10 by a fluid loss or fluid isolationvalve 20. The gravel or frac pack assembly 16 and the valve 20 generallyresemble those known and used in the art. That is, the gravel or fracpack assembly 16 enables the fracturing of various zones whilecontrolling sand or other downhole solids, while the valve 20 takes theform of a ball valve that is transitionable between a closedconfiguration (shown in FIG. 1) and an open configuration (discussedlater) due to cycling the pressure experienced by the valve 20 or othermechanical means, e.g., through an intervention with wireline or tubing.Of course, known types of fluid loss valves other than ball valves couldbe used in place of the valve 20. Additionally, it is to be appreciatedthat the lower completion 14 could include components and assembliesother than, or in addition to, the frac pack and/or gravel pack assembly16, such as for enabling stimulation, hydraulic fracturing, etc.

The system 10 also includes a work string 22 that enables anintermediate completion assembly 24 to be run in. Essentially, theassembly 24 is arranged for functionally replacing the valve 20. Thatis, while the valve 20 remains physically downhole, the assembly 24assumes or otherwise takes off at least some functionality of the valve20, i.e., the assembly 24 provides isolation of the lower completion 14and the formation and/or portion of the borehole 12 in which the lowercompletion 14 is positioned. Specifically, in the illustratedembodiment, the assembly 24 in the illustrated embodiment is a fluidloss and isolation assembly and includes a barrier valve 26 and aproduction packer or packer device 28. By packer device, it is generallymeant any assembly arranged to seal an annulus, isolation a formation orportion of a borehole, anchor a string attached thereto, etc. Thebarrier valve 26 is shown in more detail in FIG. 1A. Initially, as shownin FIGS. 1 and 1A, a shifting tool 30 holds a sleeve 32 of the barriervalve 26 in an open position by an extension 34 of the shifting tool 30that extends through the packer 28. The term “shifting tool” is usedbroadly and encompasses seal assemblies and devices that allow relativemovement or shifting of the sleeve 32 other than the tool 30 asillustrated. When the sleeve 32 is in its open position, a set of ports36 in the sleeve 32 are axially aligned with a set of ports 38 in ahousing or body 40 of the barrier valve 26, thereby enabling fluidcommunication through the barrier valve 26. Of course, movement of thesleeve 32 for enabling fluid communication is not limited to axial,although this direction of movement conveniently corresponds with thedirection of movement of the work string 22. In the illustratedembodiment, a shroud 44 is radially disposed with the barrier valve 26for further controlling and/or regulating the flow rate, pressure, etc.of fluid, i.e., by redirecting fluid flow from the lower completion 14out into the chamber formed by the shroud 44, and back into the barriervalve 26 via the ports 36 and 38 when the valve 26 is open. In theillustrated embodiment, the extension 34 of the shifting tool 30 (and/orthe sleeve 32) includes a releasable connection 46 for enablingreleasable or selective engagement between the tool 30 and the sleeve32. For example, the connection 46 could be formed by a collet,spring-loaded or biased fingers or dogs, etc.

A method of assembling and using the completion 10 according to oneembodiment is generally described with respect to FIGS. 1-9. Asillustrated in FIG. 1, the work string 22 with the assembly 24 isinitially run in for connection to the lower completion 14, therebyproviding a fluid pathway to surface and enabling production. Forexample, while circulating fluids in the borehole 12, the assembly 24can be properly positioned by lowering the work string 22 untilcirculation stops. After noting the location and slacking off on thework string, the assembly 24 is landed at the lower completion 14, asshown in FIG. 2. Once landed at the lower completion 14, the productionpacker 28 is set, e.g., via hydraulic pressure in the work string 22,thereby isolating and anchoring the assembly 24. At this point, thebarrier valve 26 is open and an equalizing port 48 between the interiorof the work string 22 and an annulus 50 is closed by the extension 34 ofthe shifting tool 30.

As illustrated in FIG. 3, the work string 22 can then be pulled out inorder to axially misalign the ports 36 and 38, which closes the barriervalve 26. That is, as shown in more detail in FIG. 3A, communicationthrough the port 38 and into the barrier valve 26 is prevented by a pairof seal elements 52 sealed against the sleeve 32. As also shown in moredetail in FIG. 3A, pulling out the work string 22 slightly also opensthe equalizing port 48, enabling the packer 28 to be tested on theannulus 50 and/or down the work string 22.

As depicted in FIG. 4, by again slacking off on the work string 22, thebarrier valve 26 re-opens (e.g., taking the configuration shown in FIG.1A) and pressure can be cycled in the work string 22 for opening thefluid loss valve 20. Next, as shown in FIG. 5, the work string 22 ispulled out of the borehole 12. Pulling out the work string 22 firstshifts the sleeve 32 into its closed position (e.g., as shown in FIG.3A) for the barrier valve 26. Then due to the packer 28 anchoring theassembly 14, continuing to pull out the work string 22 disconnects thetool 30 from the sleeve 32 at the releasable connection 46.

In order to start production, a production string 54 is run and engagedwith the assembly 24 as shown in FIGS. 6 and 7. The production string 54includes a shifting tool 56 similar to the tool 30, i.e., arranged witha releasable connection to selectively open and close the barrier valve26 by manipulating the sleeve 32. In this way, the production string 54is first landed at the assembly 24 and the tool 30 extended through thepacker 28 for shifting the sleeve 32 to open the barrier valve 26. Oncethe barrier valve 26 is opened, a tubing hanger supporting theproduction string 54 is landed and fluid from the downhole zones, i.e.,proximate to the frac or gravel pack assembly 16, can be produced. Inthe illustrated embodiment the production string 54 takes the form of anartificial lift system, particularly an ESP system for a deepwater well,which are generally known in the art. However, it is to be appreciatedthat the current invention as disclosed herein could be used innon-deepwater wells, without artificial lift systems, with other typesof artificial lift systems, etc.

Workovers are a necessary part of the lifecycle of many wells. ESPsystems, for example, are typically replaced about every 8-10 years, orsome other amount of time. Other systems, strings, or components in theupper completion 18 may need to be similarly removed or replacedperiodically, e.g., in the event of a fault, damage, corrosion, etc. Inorder to perform the workover, reverse circulation may be performed byclosing a circulation valve 58 and shifting open a hydraulic slidingsleeve 60 of the production string 54. Advantageously, if the productionstring 54 or other portions in the upper completion 18 (i.e., up-hole ofthe assembly 24) needs to be removed, removal of that portion will“automatically” revert the barrier valve 26 to its closed position,thereby preventing fluid loss. That is, the same act of pulling out theupper completion string, e.g., the production string 54, the work string22, etc., will also shift the sleeve 32 into its closed position andisolate the fluids in the lower completion. This eliminates the need forexpensive and additional wireline intervention, hydraulic pressurecycling, running and/or manipulating a designated shifting tool, etc.The packer 28 also remains in place to maintain isolation. This avoidsthe need for expensive and time consuming processes, such as wirelineintervention, which may otherwise be necessary to close a fluid lossvalve, e.g., the valve 20.

A replacement string, e.g., a new production string resembling thestring 54, can be run back down into the same intermediate completionassembly, e.g., the assembly 24. Alternatively, if a long period of timehas elapsed, e.g., 8-10 years as indicated above with respect to ESPsystems, it may instead be desirable to run in a new intermediatecompletion assembly, as equipment wears out over time, particularly inthe relatively harsh downhole environment. For example, as shown inFIGS. 8 and 9 an additional or subsequent intermediate completionassembly 24′ is run in on a work string 22′ for engagement with theoriginal assembly 24. As noted above with respect to the valve 20, thesubsequent assembly 24′ essentially functionally replaces the originalassembly 24. That is, the subsequent assembly 24′ substantiallyresembles the original assembly 24, including a barrier valve 26′ forpreventing fluid loss, a production packer 28′ for reestablishingisolation, and a sleeve 32′ that is manipulated by a shifting tool 30′on the work string 22′. It should be appreciated that the aforementionedcomponents associated with the assembly 24′ include prime symbols, butotherwise utilize the same base reference numerals as correspondingcomponents described above with respect to the assembly 24, and theabove descriptions generally apply to the corresponding componentshaving prime symbols and of the assembly 24′ (even if unlabeled), unlessotherwise noted.

Unlike the assembly 24, the assembly 24′ has a shifting tool 62 forshifting the sleeve 32 of the original assembly 24 in order to open thebarrier valve 26, which was closed by the shifting tool 56 when theproduction string 54 was pulled out. As long as the assembly 24′ remainsengaged with the assembly 24, the tool 62 will mechanically hold thebarrier valve 26 in its open position. In this way, the assembly 24′ canbe stacked on the assembly 24 and the barrier valve 26′ will essentiallytake over the fluid loss functionality of the barrier valve 26 of theassembly 24 by holding the barrier valve 26 open with the tool 62. It isto be appreciated that any number of these subsequent assemblies 24′could continue to be stacked on each other as needed. For example, a newone of the assemblies 24′ could be stacked onto a previous assemblybetween the acts of pulling out an old upper completion or productionstring and running in a new one. In this way, the newly run uppercompletion or production string will interact with the uppermost of theassemblies 24′ (as previously described with respect to the assembly 24and the production string 54), while all the other intermediateassemblies are held open by the shifting tools of the subsequentassemblies (as previously described with respect to the assembly 24 andthe shifting tool 62).

The shifting tool 30′ also differs from the shifting tool 30 to which itcorresponds. Specifically, the shifting tool 30′ includes a seat 64 forreceiving a ball or plug 66 that is dropped and/or pumped downhole. Byblocking flow through the seat 64 with the plug 66, fluid pressure canbe built up in the work string 22′ suitable for setting and anchoringthe production packer 28′. That is, pressure was able to be establishedfor setting the original packer 28 because the fluid loss valve 20 wasclosed, but with respect to FIGS. 8 and 9 the valve 20 has since beenopened and fluid communication established with the lower completion 14as described previously.

After setting the packer 28′, the string 22′ can be pulled out, therebyautomatically closing the sleeve 32′ of the barrier valve 26′ aspreviously described with respect to the assembly 24 and the work string22 (e.g., by use of a releasable connection). As previously noted, theoriginal barrier valve 26 remains opened by the shifting tool 62 of thesubsequent assembly 24′. As the assembly 24′ has essentially taken overthe functionality of the original assembly 24 (i.e., by holding thebarrier valve 26 constantly open with the tool 62), a new productionstring, e.g., resembling the production string 54, can be run inessentially exactly as previously described with respect to theproduction string 54 and the assembly 24, but instead engaged with theassembly 24′. That is, instead of manipulating the barrier valve 26, theshifting tool (e.g., resembling the tool 56) of the new productionstring (e.g., resembling the string 54) will shift the sleeve 32′ of thebarrier valve 26′ open for enabling production of the fluids from thedownhole zones or reservoir.

It is again to be appreciated that any number of the assemblies 24′ cancontinue to be run in and stacked atop one another. For example, thisstacking of the assemblies 24′ can occur between the acts of pulling outan old production string and running a new production string, with thepulling out of each production string “automatically” closing theuppermost one of the assemblies 24′ and isolating the fluid in the lowercompletion 14. In this way, any number of production strings, e.g., ESPsystems, can be replaced over time without the need for expensive andtime consuming wireline intervention, hydraulic pressure cycling,running and/or manipulation of a designated shifting tool, etc.Additionally, the stackable nature of the assemblies 24, 24′, etc.,enables the isolation and fluid loss hardware to be refreshed or renewedover time in order to minimize the likelihood of a part failure due towear, corrosion, aging, etc.

It is noted that the fluid loss valve 20 can be substituted, forexample, by the assembly 24 being run in on a work string resembling thework string 22′ as opposed to the work string 22. For example, as shownin FIG. 10, a modified system 10 a includes the assembly 24 being run inon the work string 22′. In this way, fluid pressure suitable for settingthe original packer 28 can be established by use of the ball seat 64 andthe plug 66 instead of the valve 20. Accordingly, as illustrated in FIG.10, the fluid loss valve 20 is rendered unnecessary or redundant by useof the system 10 a, as the plug 66 and the seat 64 of the work string22′ enable suitable pressurization for setting the packer 28, and thetool 30′ of the work string 22′ enables control of the barrier valve 26such that the assembly 24 can completely isolate the lower completion14. After isolating the lower completion 14, a production string, e.g.,the string 54, subsequent intermediate assemblies, etc., can be run inand interact with the assembly 24 as described above.

As another example, a modified system 10 b is illustrated in FIG. 11.The system 10 b is similar to the system 10 a in that a separate fluidisolation valve for the lower completion 14, e.g., the valve 20, is notnecessary and instead the system 10 b can be run in for initiallyisolating the lower completion 14. Unlike the system 10 a, the system 10b is capable of being run-in immediately on the production string 54without the need for the work string 22′ of the system 10 a.Specifically, the system 10 b is run-in with a plug 66′ already locatedin a shifting tool 56′ of the production string 54. The tool 56′resembles the tool 56 with the exception of being arranged to hold theplug 66′ therein for blocking fluid flow therethrough. By running theplug 66′ in with the system 10 b, the plug 66′ does not need to bedropped and/or pumped from surface, as this would be impossible forvarious configurations of the production string 54, e.g., if the string54 includes ESPs or other components or assemblies that would obstructthe pathway of a dropped plug down through the string. The plug 66′ isarranged to be degradable, consumable, disintegrable, corrodible,dissolvable, chemically reactable, or otherwise removable so that onceit has been used for providing the hydraulic pressure necessary to setthe packer 28, the plug 66′ can be removed and enable production throughthe string 54. In one embodiment the plug 66′ is made from a dissolvableor reactive material, such as magnesium or aluminum that can be removedin response to a fluid deliverable or available downhole, e.g., acid,brine, etc. In another embodiment, the plug 66′ is made from acontrolled electrolytic material, such as made commercially available byBaker Hughes, Inc. under the tradename IN-TALLIC®. Once the plug 66′ isremoved, the system 10 b would function as described above with respectto the system 10.

It is thus noted that the current invention as illustrated in FIGS. 1-9is suitable as a retrofit for systems that are in need of a workover,i.e., need to have the upper completion replaced or removed, but alreadyincludes a valve resembling the fluid loss valve 20 (e.g., a ball valveor some other type of valve used in the art that requires wirelineintervention, hydraulic pressure cycling, the running and/ormanipulation of designated shifting tools, etc., in order to transitionbetween open and closed configurations). Alternatively stated, thesystem 10 enables downhole isolation of a lower completion forperforming a workover, i.e., removal or replacement of an uppercompletion, without the need for time consuming wireline or otherintervention.

In view of the foregoing it is to be appreciated that new completionscan be installed with a valve, e.g., the fluid loss valve 20, thatrequires some separate intervention and/or operation to close the valveduring workovers, or, alternatively, according to the systems 10 a or 10b, which not only initially isolate a lower completion, e.g., the lowercompletion 14, but additionally include a barrier valve, e.g., thebarrier valve 26, that automatically closes upon pulling out the uppercompletion, as described above.

While the invention has been described with reference to an exemplaryembodiment or embodiments, it will be understood by those skilled in theart that various changes may be made and equivalents may be substitutedfor elements thereof without departing from the scope of the invention.In addition, many modifications may be made to adapt a particularsituation or material to the teachings of the invention withoutdeparting from the essential scope thereof Therefore, it is intendedthat the invention not be limited to the particular embodiment disclosedas the best mode contemplated for carrying out this invention, but thatthe invention will include all embodiments falling within the scope ofthe claims. Also, in the drawings and the description, there have beendisclosed exemplary embodiments of the invention and, although specificterms may have been employed, they are unless otherwise stated used in ageneric and descriptive sense only and not for purposes of limitation,the scope of the invention therefore not being so limited. Moreover, theuse of the terms first, second, etc. do not denote any order orimportance, but rather the terms first, second, etc. are used todistinguish one element from another. Furthermore, the use of the termsa, an, etc. do not denote a limitation of quantity, but rather denotethe presence of at least one of the referenced item.

What is claimed is:
 1. A completion system, comprising: a lowercompletion initially fluidly open; a production string having aremovable plug configured to impede fluid flow through the productionstring, the removable plug being run in with the production string; andan intermediate completion assembly coupling the lower completion to theproduction string, the intermediate completion assembly having a packerdevice and a barrier valve, the packer device operatively arranged to beset by pressurizing fluid in the production string against the removableplug, the barrier valve operatively arranged for selectively impedingfluid flow between the production string and the lower completion afterthe removable plug is removed.
 2. The completion system of claim 1,wherein the removable plug is operatively arranged to be removed byexposure to a downhole fluid.
 3. The completion system of claim 1,wherein the downhole fluid comprises brine, acid, water, oil, or acombination including at least one of the foregoing.
 4. The completionsystem of claim 1, wherein the production string comprises an artificiallift system.
 5. The completion system of claim 1, wherein the productionstring includes at least one component prohibiting passage of a pluggingimplement therethrough.
 6. The completion system of claim 1, wherein thebarrier valve is operatively arranged to be transitionable to an openposition when engaged with the upper completion string and transitioningto a closed position via the upper completion string when the uppercompletion string is pulled out of the borehole.
 7. The completionsystem of claim 1, further comprising a subsequent intermediate assemblystacked with the intermediate completion assembly, the subsequentintermediate assembly having a subsequent barrier valve and a subsequentpacker device for functionally replacing the intermediate completionassembly.
 8. The completion system of claim 7, wherein the intermediatecompletion assembly is engaged between the subsequent intermediateassembly and the lower completion and the subsequent intermediateassembly is engaged between the intermediate completion assembly and theproduction string.
 9. The completion system of claim 8, wherein theproduction string includes a first tool operatively arranged forenabling the subsequent barrier valve to transition between open andclosed positions and the subsequent intermediate assembly is arrangedwith a second tool for holding the barrier valve in its open positionwhile the subsequent intermediate completion assembly is engaged withthe first intermediate assembly.
 10. The completion system of claim 1,wherein the intermediate completion assembly includes a shroud enclosinga housing of the barrier valve.
 11. A method of completing a boreholecomprising: running a production string having a removable plug disposedtherewith downhole, an intermediate completion assembly disposed withthe production string; coupling the production string to a lowercompletion with the intermediate completion assembly, the lowercompletion initially fluidly open; impeding fluid flow between theproduction string and the lower completion with the removable plug;setting a packer device by pressurizing fluid in the production stringagainst the removable plug; removing the removable plug; and impedingfluid flow between the production string and the lower completion with abarrier valve of the intermediate completion assembly.
 12. The method ofclaim 11, further comprising exposing the removable plug to a downholefluid for removing the removable plug.
 13. The method of claim 11,wherein the downhole fluid comprises brine, acid, water, oil, or acombination including at least one of the foregoing.
 14. The method ofclaim 11, wherein the production string comprises an artificial liftsystem.
 15. The method of claim 11, wherein the production stringincludes at least one component prohibiting passage of a pluggingimplement therethrough.
 16. The method of claim 11, wherein the barriervalve is operatively arranged to be transitionable to an open positionwhen engaged with the upper completion string and transitioning to aclosed position via the upper completion string when the uppercompletion string is pulled out of the borehole.
 17. The method of claim11, further comprising running in a subsequent intermediate assembly andstacking the subsequent intermediate assembly with the intermediatecompletion assembly, the subsequent intermediate assembly having asubsequent barrier valve and a subsequent packer device for functionallyreplacing the intermediate completion assembly.
 18. The system of claim17, wherein the intermediate completion assembly is engaged between thesubsequent intermediate assembly and the lower completion and thesubsequent intermediate assembly is engaged between the intermediatecompletion assembly and the production string.
 19. The system of claim18, wherein the production string includes a first tool operativelyarranged for enabling the subsequent barrier valve to transition betweenopen and closed positions and the subsequent intermediate assembly isarranged with a second tool for holding the barrier valve in its openposition while the subsequent intermediate completion assembly isengaged with the first intermediate assembly.